1. Field of the Invention
The present invention is directed to particulate substrates coated with a resin comprising bisphenol-aldehyde novolak polymer or a bisphenol homopolymer. Depending upon the resin selected, the substrate selected and how the resin is combined with the substrate, the resulting resin coated particle is useful in either subterranean formations as a proppant or in shell cores and molds for the foundry industry. The present invention also relates to methods of making or using the resins or coated substrates.
2. Description of Background Art
The use of phenolic resin coated proppants is disclosed by U.S. Pat. No. 5,218,038 to Johnson et al (the disclosure of which is incorporated by reference in its entirety). In general, proppants are extremely useful to keep open fractures imposed by hydraulic fracturing upon a subterranean formation, e.g., an oil or gas bearing strata. Typically, the fracturing is desired in the subterranean formation to increase oil or gas production. Fracturing is caused by injecting a viscous fluid or a foam at high pressure into the well and placing a particulate material, referred to as a "propping agent" or "proppant" in the formation to maintain the fracture in a propped condition when the injection pressure is released. The proppants are carried into the well by suspending them in the fluid or foam. As the fracture forms, it is filled with proppant and fluid or foam. Upon release of the pressure, the proppants form a pack which serves to hold open the fractures. The goal of using proppants is to increase production of oil and/or gas by providing a highly conductive channel in the formation. Choosing a proppant is critical to the success of well stimulation.
The propped fracture thus provides a highly conductive channel in the formation. The degree of stimulation afforded by the hydraulic fracture treatment is largely dependent upon the permeability and width of the propped fracture. If the proppant is an uncoated substrate and is subjected to high stresses existing in a gas/oil well, the substrate may be crushed to produce fines. Fines will subsequently reduce conductivity within the proppant pack. However, a resin coating will enhance crush resistance of a coated particle above that of the substrate alone.
Known resins used in resin coated proppants include epoxy, furan, phenolic resins and mixtures of these resins. The resins are from about 1 to about 8 percent by weight of the total coated particle. The particulate substrate may be sand, ceramics, or other particulate substrate and has a particle size in the range of USA Standard Testing screen numbers from about 8 to about 100 (i.e. screen openings of about 0.0937 inch to about 0.0059 inch).
Resin coated proppants come in two types: precured and curable. Precured resin coated proppants comprise a substrate coated with a resin which has been significantly crosslinked. The resin coating of the precured proppants provides crush resistance to the substrate. Since the resin coating is already cured before it is introduced into the well, even under high pressure and temperature conditions, the proppant does not agglomerate. Such precured resin coated proppants are typically held in the well by the stress surrounding them. In some hydraulic fracturing circumstances, the precured proppants in the well would flow back from the fracture, especially during clean up or production in oil and gas wells. Some of the proppant can be transported out of the fractured zones and into the well bore by fluids produced from the well.
Flowing back of proppant from the fracture is undesirable and has been controlled to an extent in some instances by the use of a proppant coated with a curable resin which will consolidate and cure underground. Phenolic resin coated proppants have been commercially available for some time and used for this purpose. Thus, resin-coated curable proppants may be employed to "cap" the fractures to prevent such flow back. The resin coating of the curable proppants is not significantly crosslinked or cured before injection into the oil or gas well. Rather, the coating is designed to crosslink under the stress and temperature conditions existing in the well formation. This causes the proppant particles to bond together forming a 3-dimensional matrix and preventing proppant flowback.
These curable phenolic resin coated proppants work best in environments where temperatures are sufficiently high to consolidate and cure the phenolic resins. However, conditions of geological formations vary greatly. In some gas/oil wells, high temperature (&gt;180.degree. F.) and high pressure (&gt;6,000 psi) are present downhole. Under these conditions, most curable proppants can be effectively cured. Moreover, proppants used in these wells need to be thermally and physically stable, i.e. do not crush appreciably at these temperatures and pressures.
Many shallow wells often have downhole temperatures less than 130.degree. F., or even less than 100.degree. F. Conventional curable proppants will not cure properly at these temperatures. Sometimes, an activator can be used to facilitate curing at low temperatures. Another method is to catalyze proppant curing at low temperatures using an acid catalyst in an overflush technique. Systems of this type of curable proppant have been disclosed in U.S. Pat. No. 4,785,884 and the disclosure of this patent is incorporated by reference in its entirety. In the overflush method, after the curable proppant is placed in the fracture, an acidic catalyst system is pumped through the proppant pack and initiates the curing even at low temperatures (about 100.degree. F.). This causes the bonding of proppant particles.
Due to the diverse variations in geological characteristics of different oil and gas wells, no single proppant possesses all properties which can satisfy all operating requirements under various conditions. The choice of whether to use a precured or curable proppant or both is a matter of experience and knowledge as would be known to one skilled in the art.
In use, the proppant is suspended in the fracturing fluid. Thus, interactions of the proppant and the fluid will greatly affect the stability of the fluid in which the proppant is suspended. The fluid needs to remain viscous and capable of carrying the proppant to the fracture and depositing the proppant at the proper locations for use. However, if the fluid prematurely loses its capacity to carry, the proppant may be deposited at inappropriate locations in the fracture or the well bore. This may require extensive well bore cleanup and removal of the mispositioned proppant.
It is also important that the fluid breaks (undergoes a reduction in viscosity) at the appropriate time after the proper placement of the proppant. After the proppant is placed in the fracture, the fluid shall become less viscous due to the action of breakers (viscosity reducing agents) present in the fluid. This permits the loose and curable proppant particles to come together, allowing intimate contact of the particles to result in a solid proppant pack after curing. Failure to have such contact will give a much weaker proppant pack.
Foam, rather than viscous fluid, may be employed to carry the proppant to the fracture and deposit the proppant at the proper locations for use. The foam is a stable foam that can suspend the proppant until it is placed into the fracture, at which time the foam breaks. Agents other than foam or viscous fluid may be employed to carry proppant into a fracture where appropriate.
While useful proppants are known, it would be beneficial to provide proppants having improved features such as compressive strength as well as higher long term conductivity, i.e., permeability, at the high closure stresses present in the subterranean formation. Improved compressive strength better permits the proppant to withstand the forces within the subterranean formation. High conductivity is important because it directly impacts the future production rate of the well. It would also be beneficial to provide proppants which minimize or eliminate free phenol or hexamethylenetetramine (HEXA) in the resin. Any free phenol and HEXA are prone to water dissolution under down-hole applications. This can affect other fluid parameters, such as breaker interaction, high temperature stability, etc.
Another use of sand or other particulate substrates coated with resin is in the foundry industry. However, in the foundry industry, the resin is typically from about 1 to about 6 percent by weight of the coated particle. Moreover, resin coated foundry particulates have a particle size in the range of USA Standard Testing screen numbers from 16 to about 270 (i.e., a screen opening of 0.0469 inch to 0.0021 inch).
Typically the particulate substrates for foundry use are granular refractory aggregate. Examples of refractory aggregates include silica sand, chromite sand, zircon sand, olivine sand and mixtures thereof. For purposes of the disclosure of the present invention such materials are referred to as "sand" or "foundry sand".
In the foundry art, cores or molds for making metal castings are normally prepared from a mixture of aggregate material, such as foundry sand, and a binding amount of a binder or binder system. A number of binders or binder systems for foundry cores and molds are known. Typically, after the aggregate material and binder have been mixed, the resulting mixture is rammed, blown or otherwise formed to the desired shape or pattern, and then cured to a solid, cured state. A variety of processes have been developed in the foundry industry for forming and curing molds and cores.
One popular foundry process is known as the Croning or C process (more commonly known as the shell process). In this process, foundry sand is coated with a thermoplastic resin, a crosslinker and optionally other additives. Thermoplastic resin can be in solid form or in solution with a volatile organic solvent or mixtures of solvent and water. If the thermoplastic resin is a solid, the coating process requires the sand be heated to temperatures above the resin's melting point. Then the resin, crosslinker and other additives are coated evenly on the foundry sand to give a curable coating composition.
If the resin is in a solution, sand can be coated at temperatures at which the solvent can be readily removed. This process is also referred to as the liquid shell process. Frequently, crosslinker and additives are dissolved (or dispersed) in the solvent with the resin. The resinous mixture is added to warm sand. With agitation, the solvent is removed, leaving a curable coating on the sand particles. It is also possible to incorporate resin additives at other steps of the coating process.
In either cases, a curable resin composition is coated onto the sand to form free flowing resin coated sand (particles). Subsequently, the resin coated sand is packed into a heated mold, usually at 350.degree. to 750.degree. F. to initiate curing of the thermoplastic polymer by reaction with the crosslinker to form thermosetting polymer. After the curing cycle, a shell of cured resin coated sand is formed adjacent to the heated surface. Depending upon the shape of the heated surfaces, shell molds and cores can be made and used in a foundry by this method.
While the above phenol-formaldehyde resins have been used as binders in these processes for making foundry shell cores and molds, they have limitations. It would be beneficial to provide an alternative to the resins typically employed for coating foundry sand. Such an alternative would be especially desirable if it minimizes or eliminates free phenol to be more environmentally acceptable, has a higher melt point to reduce caking or lumping during storage, or has a higher tensile strength to reduce the amount of resin employed. It would also be desirable if the alternative has higher plasticity, to be less prone to thermal shock, and faster resin breakdown, to achieve better shakeout characteristics.